WO2015038100A1

WO2015038100A1 - Realtime downhole sample volume collection

Info

Publication number: WO2015038100A1
Application number: PCT/US2013/059026
Authority: WO
Inventors: Scott L. Miller; Gregory T. WERKHEISER
Original assignee: Halliburton Energy Services. Inc.
Priority date: 2013-09-10
Filing date: 2013-09-10
Publication date: 2015-03-19
Also published as: US20160177713A1; BR112015032079A2

Abstract

A method and apparatus for realtime downhole sample volume collection is described. The sampler apparatus includes a sample chamber and a sensor for real-time measurement disposed proximate to the sample chamber. In one embodiment, the sample chamber may include a piston, and the sensor may be mounted on the piston. The sensor may comprise a flow meter, a light sensor, a capacitive sensor, a resistive sensor, a movement sensor, an acceleration sensor, a continuity sensor, or other sensor types known to those of skill in the art, and it may measure fluid volume, pressure, composition, or other properties. Optionally, a telemetry system may be included to transmit the real-time sensor measurements to the surface.

Description

REALTIME DOWNHOLE SAMPLE VOLUME COLLECTION

BACKGROUND

The present disclosure relates generally to oil field exploration and, more particularly, to a system and method for realtime downhole sample volume collection via telemetry.

It is well known in the subterranean well drilling and completion art to perform tests on formations intersected by a wellbore. Such tests are typically performed in order to determine geological or other physical properties of the formation and fluids contained therein. For example, parameters such as permeability, porosity, fluid resistivity, temperature, pressure and bubble point may be determined. These and other characteristics of the formation and fluid contained therein may be determined by performing tests on the formation before the well is completed.

One type of testing procedure that is commonly performed is to obtain a fluid sample from the formation to, among other things, determine the composition of the formation fluids. In this procedure, it is important to obtain a sample of the formation fluid that is representative of the fluids as they exist in the formation. In a typical sampling procedure, a sample of the formation fluids may be obtained by lowering a sampling tool having a sampling chamber into the wellbore on a conveyance such as a wireline, slick line, coiled tubing, jointed tubing or the like. When the sampling tool reaches the desired depth, one or more ports are opened to allow collection of the formation fluids. The ports may be actuated in variety of ways such as by electrical, hydraulic or mechanical methods. Once the ports are opened, formation fluids travel through the ports and a sample of the formation fluids is collected within the sampling chamber of the sampling tool. After the sample has been collected, the sampling tool may be withdrawn from the wellbore so that the formation fluid sample may be analyzed.

Under that traditional approach, the integrity of the sample may not be verified until the sampling tool is withdrawn from the wellbore. If a sampling error has occurred, such as a failure to retain a sample, then the sampling tool must be redeployed and the sampling process restarted. This may result in unnecessary and costly tripping of the sampling tool. Further, even if a sample is successfully captured, any analysis of that sample similarly must be deferred until after the sampling tool is withdrawn. FIGURES

Some specific exemplary embodiments of the disclosure may be understood by referring, in part, to the following description and the accompanying drawings.

FIG. 1 illustrates an example drilling system.

FIG. 2 illustrates a representative fluid sampler system.

FIG. 3 shows an exemplary embodiment of a sampler according to the present disclosure using a flow meter for real-time measurement.

FIG. 4 shows an exemplary embodiment of a sampler according to the present disclosure that uses a piston-mounted sensor for real-time measurement.

FIGS. 5A-B illustrate exemplary piston and sensor configurations.

While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.

DETAILED DESCRIPTION

Illustrative embodiments of the present disclosure are described in detail herein.

In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the specific implementation goals, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.

To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the disclosure. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, multilateral, u-tube connection, intersection, bypass (drill around a mid-depth stuck fish and back into the well below), or otherwise nonlinear wellbores in any type of subterranean formation. Embodiments may be applicable to injection wells, and production wells, including natural resource production wells such as hydrogen sulfide, hydrocarbons or geothermal wells; as well as borehole construction for river crossing tunneling and other such tunneling boreholes for near surface construction purposes or borehole u-tube pipelines used for the transportation of fluids such as hydrocarbons. Devices and methods in accordance with embodiments described herein may be used in one or more of measurement- while-drilling ("MWD") and logging-while-drilling ("LWD") operations. Embodiments described below with respect to one implementation are not intended to be limiting.

FIG. 1 is a diagram illustrating an example drilling system 100, according to aspects of the present disclosure. The drilling system 100 includes rig 101 at the surface 1 1 1 and positioned above borehole 103 within a subterranean formation 102. Rig 101 may be coupled to a drilling assembly 104, comprising drill string 105 and bottom hole assembly 106. The bottom hole assembly 106 may comprise a drill bit 109, steering assembly 108, and a LWD/MWD apparatus 107. A control unit 1 14 at the surface may comprise a processor and memory device, and may communicate with elements of the bottom hole assembly 106, including LWD/MWD apparatus 107 and steering assembly 108. The control unit 1 14 may receive data from and send control signals to the bottom hole assembly 106. Additionally, at least one processor and memory device may be located downhole within the bottom hole assembly 106 for the same purposes. The LWD/MWD apparatus 107 may comprise at least one fluid sampler system as well as various other measuring or logging assemblies that would be appreciated by one of ordinary skill in the art in view of this disclosure.

FIG. 2 illustrates an example fluid sampler system 200 and associated methods that embody aspects of the present disclosure. A tubular string 212, such as a drill stem test string, is positioned in a wellbore 214. An internal flow passage 216 extends longitudinally through tubular string 212.

In the embodiment shown, a fluid sampler 218 is coupled to the tubular string 212. In other embodiments, the fluid sampler 218 may be deployed downhole using a wireline, slickline, coiled tubing, downhole robot, etc., rather than tubular string 212 A circulating valve 220, a tester valve 222 and a choke 224 also may be coupled to the tubular string 212. Circulating valve 220, tester valve 222 and choke 224 may be of conventional design. Aswould be appreciated by one of ordinary skill in the art in view of this disclosure, it is not necessary for tubular string 212 to include any specific combination or arrangement of equipment described herein. Additionally, although wellbore 214 is depicted as being cased and cemented, it could alternatively be uncased or open hole.

In an example formation testing operation, tester valve 222 is used to selectively permit and prevent flow through passage 216. Circulating valve 220 is used to selectively permit and prevent flow between passage 216 and an annulus 226 formed radially between tubular string 212 and wellbore 214. Choke 224 is used to selectively restrict flow through tubular string 212. Each of valves 220, 222 and choke 224 may be operated by manipulating pressure in annulus 226 from the surface, or any of them could be operated by other methods if desired.

Choke 224 may be actuated to restrict flow through passage 216 to minimize wellbore storage effects due to the large volume in tubular string 212 above sampler 218. When choke 224 restricts flow through passage 216, a pressure differential is created in passage 216, thereby maintaining pressure in passage 216 at sampler 218 and reducing the drawdown effect of opening tester valve 222. In this manner, by restricting flow through choke 224 at the time a fluid sample is taken in sampler 218, the fluid sample may be prevented from going below its bubble point, i.e., the pressure below which a gas phase begins to form in a fluid phase. Circulating valve 220 permits hydrocarbons in tubular string 212 to be circulated out prior to retrieving tubular string 212. Circulating valve 220 also allows increased weight fluid to be circulated into wellbore 214.

Although FIGS. 1-2 depict a vertical well, it should be noted by one skilled in the art that the fluid sampler of the present disclosure is equally well-suited for use in deviated wells, inclined wells or horizontal wells. As such, the use of directional terms such as above, below, upper, lower, upward, downward and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure.

FIG. 3 shows an exemplary embodiment of a sampler 300 according to the present disclosure. The sampler may include a sampler carrier 360 with a sample chamber 340 and an inlet 320 coupled to the sample chamber 340. A sensor for real-time measurement 330 may be disposed proximate to the sample chamber 340. Real-time measurement may comprise taking of measurements at the time the sample is acquired or after the sample is acquired but while the sampler remains downhole. Measurements may include, for example, the volume, pressure, position, and composition of a sample, and/or may include any of the other measurements made by sensors found in production logging tools. In the embodiment shown, the sensor for real-time measurement comprises a flow meter 330. As shown in FIG. 3, the oil or other fluid to be sampled moves through a passage 310. It may be taken into sampler 340 via inlet 320.

Flow meter 330 is disposed within inlet 320 such that as oil or other fluids flow from passage 310 to sampler 340, they pass through flow meter 330. In the embodiment of FIG. 3, flow meter 330 is shown as an impeller-type flow meter. An impeller-type flow meter may contain rotatable blades that are rotated by the passage of liquid. The blades may be configured so that the inflow of liquid causes rotational movement of the blades in one direction, while the outflow of liquid causes rotational movement of the blades in the opposite direction. In the embodiment shown, for example, the movement of liquid into sampler 340 from passage 310 via inlet 320 may cause the blades of flow meter 330 to rotate in a clockwise direction; by comparison, the movement of liquid out of sampler 340 back into passage 310 via inlet 320 may cause the blades of flow meter 330 to rotate in a counter-clockwise direction. In this way, a person of ordinary skill in the art will appreciate that the amount of fluid entering our exiting sampler 340 may be determined by measuring the direction and magnitude of blade rotation.

Although the embodiment of FIG. 3 shows the sensor as an impeller-type flow meter, other types of sensors known to those of skill in the art may be used consistent with the present disclosure. For example, other types of flow-meters may be used, such as an infrared sensor or a light sensor that detects the movement of fluid. In addition, the sensor may take other types of measurements of the sample, for example measurements regarding the volume, pressure, position, and composition of the sample. The sensor 330 may therefore include a light sensor that determines the type of gas or capacitive sensors, resistive sensors, movement sensors, acceleration sensors, or continuity sensors. As one of skill in the art will appreciate, the sensor 330 may include any of the sensors commonly found in production logging tools.

Regardless of the type of flow meter employed, flow meter 330 may be used to measure the inflow and outflow of fluid from sampler 340. The measurements may, for example, verify that fluid has begun flowing into sampler 340 at the beginning of a sample collection cycle, determine the amount of fluid that has flowed into sampler 340 during a sample collection cycle, or identify whether any fluid has flowed out of sampler 340.

The measurements performed by flow meter 330 may be communicated to a surface operator by means of telemetry communications 355, for example by using telemetry device 350. One of skill in the art will appreciate that many kinds of telemetry may be used consistent with the present disclosure, such as wired telemetry, wireless telemetry, or mud-pulse telemetry. In an alternative embodiment, discussed in more detail below with reference to the embodiment of FIG. 4, sampler 300 may have a simple telemetry system for sending short, low- power communications, and the information from sampler 300 may be relayed to the surface by a more robust telemetry system located elsewhere in the downhole tool.

Using such telemetry, a surface operator may monitor the sampler in realtime and send appropriate instructions based on the received measurements. For example, if flow meter 330 communicates a measurement showing that fluid has leaked out of sampler 340, the surface operator may initiate the collection of a replacement sample.

As one of skill in the art will appreciate, although the embodiment of FIG. 3 shows only one flow meter 330, sampler 340, and telemetry system 350 in sampler carrier 360, a sampler carrier 360 may include a plurality of flow meters, samplers, and/or telemetry systems.

FIG. 4 shows an exemplary embodiment of a sampler 400 according to the present disclosure that uses a piston-mounted sensor for real-time measurement. As in the embodiment of FIG. 3, the oil or other fluid to be sampled moves through a passage 410 and may be taken into a sampler 440 via an inlet 420. In the embodiment of FIG. 4 a piston 430 and a sensor 435 may be included in sampler 440. Various exemplary configurations for the piston and sensor are shown in FIGS. 5A-B and discussed below.

Similar to the sensor 330 of FIG. 3, the sensor 435 may take measurements of the sample, such as measurements regarding the volume, pressure, position, and composition of the sample. Sensor 435 may include a light sensor that determines the type of gas or capacitive sensors, resistive sensors, movement sensors, acceleration sensors, or continuity sensors. As one of skill in the art will appreciate, sensor 435 may include any of the sensors commonly found in production logging tools.

The measurements captured by sensor 435 may be communicated to a surface operator by means of telemetry. This may be accomplished by directly sending telemetry signals from sampler 400 to the surface, as in the embodiment shown in FIG. 3. Alternatively, as shown in the embodiment of FIG. 4, the piston 430 or sensor 435 may include a simple telemetry system for sending short, low-power communications 445. Those short low-power communications 445 may be received by a more sophisticated telemetry system 450 that is configured to send telemetry communications 455 to the surface. The simple telemetry system of piston 430 or sensor 435 may be, for example, an acoustic telemetry system. The more sophisticated telemetry system 450 may be, for example, a wired telemetry, wireless telemetry, or mud-pulse telemetry system used by other tools in a LWD/MWD apparatus.

As with FIG. 3, although FIG. 4 shows only one piston 430, sensor, 435, sampler 440, and telemetry system 450 in sampler carrier 460, a sampler carrier may include a plurality of pistons, sensors, samplers, and/or telemetry systems.

FIGS. 5A-B illustrate exemplary configurations for the piston and sensor of FIG. 4. In particular, the exemplary configurations shown include two pistons, a sample entry piston 516 and a junk piston 518. The operation of the pistons is similar in both configurations. A fluid to be sampled, for example oil, is received from an inlet (such as inlet 420 in FIG. 4) into sample fluid chamber 514. The flow between the inlet and sample fluid chamber 514 may be controlled by sample entry piston 516, for example by means of a check valve or restrictor.

A junk piston 518 may separate sample fluid chamber 514 from a displacement fluid chamber 524. In the illustrated embodiment, as fluid flows into sample chamber 514, fluid may be permitted to flow into junk chamber 526. The flow of fluid into junk chamber 526 may be controlled, for example, by a check valve on junk piston 518. As a result of fluid flowing into the junk chamber, junk chamber 526 may expand. The fluid received in junk chamber 526 is prevented from escaping back into sample chamber 514 by the junk piston, for example by means of a check valve. In this manner, the fluid initially received into sample chamber 514 is trapped in junk chamber 526. This initially received fluid is typically laden with debris, or is a type of fluid (such as mud) which it is not desired to sample. Junk chamber 526 thus permits this initially received fluid to be isolated from the fluid sample later received in sample chamber 514.

Once fluid is no longer permitted to flow from sample chamber 514 into junk chamber 526, fluid may begin to fill sample chamber 514. As the fluid sample is received in sample chamber 514, the sample chamber 514 expands and junk piston 518 is displaced downwardly. Downward displacement of the junk piston 518 may be slowed by displacement fluid in a displacement chamber 524. Displacement fluid chamber 524 may initially contain a displacement fluid, such as a hydraulic fluid, silicone oil, or the like, and the flow of displacement fluid out of displacement fluid chamber 524 may be regulated by a check valve or other flow restrictor. This may prevent pressure in the fluid sample received in the sample chamber 514 from dropping below its bubble point.

In the configuration shown in FIG. 5 A, sensor 535 is disposed proximate to the sample entry piston 516. Sample measurements may be taken as the fluid passes through sample entry piston 516. By comparison, in the configuration shown in FIG. 5B, sensor 535 is disposed proximate to the junk piston 518. Sample measurements may be taken as the fluid enters sample chamber 514 or junk chamber 526. In both configurations, electronics with a transceiver for telemetry 543 may be disposed proximate to sensor 535 and may communicate the results of the measurements.

As discussed with respect to FIG. 4, the sensor 535 may measure volume, pressure, position, and composition of a sample, and/or may include any of the sensor types found in production logging tools. Similarly, electronics with a transceiver for telemetry 543 may communicate directly with a surface operator or may communicate indirectly by sending short-range transmissions to a more sophisticated telemetry system. A bulkhead 547 is shown, which may protect electronics 543 from debris, fluids, or other materials contained within junk chamber 526.

By using a system such as the embodiment shown in FIG. 4, or either of the piston/sensor configurations shown in FIGS. 5A-B, a surface operator may measure the results of a sampling in realtime. For example, if a surface operator determines that the reported sensor measurements do not reflect the desired sample, the operator may initiate further sampling.

Thus, a person of ordinary skill in light of the present disclosure will understand that an embodiment is a sample carrier including a sample chamber and a sensor for real-time measurement positioned proximate to the sample chamber.

The sensor may optionally be a flow meter, such as an impeller-type flow meter. Additional types of sensors may include a light sensor, capacitive sensor, a movement sensor, an acceleration sensor, or a continuity sensor. The sample chamber may optionally contain one or more pistons, and the sensor may be coupled to a piston. The one or more pistons may be sampler entry pistons and/or junk pistons.

The sampler carrier may optionally include a telemetry system coupled to the sensor. The telemetry system may communication directly with a surface receiver or may communicate indirectly via a second telemetry system located downhole.

As a person of ordinary skill in light of the present disclosure will understand, an embodiment is a method for sampling, including the steps of deploying a sample chamber downhole, filling the sample chamber with fluid, and performing at least one measurement of the fluid with a sensor while the sampler is downhole.

The at least one measurement may include the fluid's volume, pressure, or composition. The method for sampling may optionally include transmitting the measurement using a telemetry system, including optionally transmitting the measurement to a second downhole telemetry system.

Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. The indefinite articles "a" or "an," as used in the claims, are defined herein to mean one or more than one of the element that it introduces. Additionally, the terms "couple", "coupled", or "coupling" include direct or indirect coupling through intermediary structures or devices.

Claims

What is claimed is:

1. A sampler carrier, comprising:

a sample chamber; and

a sensor for real-time measurement disposed proximate to said sample chamber.

2. The sampler carrier of claim 1, wherein said sensor is a flow meter.

3. The sampler carrier of claim 2, wherein said flow meter is an impeller flow meter.

4. The sampler carrier of claim 1, further comprising a piston disposed within said sampler chamber, wherein said sensor is coupled to said piston.

5. The sampler carrier of claim 4, wherein said sensor comprises at least one of a flow meter, a light sensor, a capacitive sensor, a resistive sensor, a movement sensor, an acceleration sensor, or a continuity sensor.

6. The sampler carrier of claim 4, wherein said piston is a sampler entry piston.

7. The sampler carrier of claim 4, wherein said piston is a junk piston.

8. The sampler carrier of claim 1, further comprising a telemetry system communicatively coupled to said sensor.

9. The sampler carrier of claim 8, wherein said telemetry system communicates directly with a surface receiver.

10. The sampler carrier of claim 8, wherein said telemetry system communicates indirectly with a surface receiver via a second downhole telemetry system.

1 1. A method for sampling, comprising:

deploying a sample chamber downhole;

filling said sample chamber with a downhole fluid; and

performing at least one measurement of said fluid with a sensor proximate to said sample chamber while said sample chamber is downhole.

12. The method of claim 1 1 , wherein said sensor is a flow meter.

13. The method of claim 12, wherein said flow meter is an impeller flow meter.

14. The method of claim 1 1, wherein said sensor is coupled to a piston.

15. The method of claim 14, wherein said piston is a sampler entry piston.

16. The method of claim 14, wherein said piston is a junk piston.

17. The method of claim 11, wherein said sensor comprises at least one of a flow meter, a light sensor, a capacitive sensor, a resistive sensor, a movement sensor, an acceleration sensor, or a continuity sensor.

18. The method of claim 17, wherein said at least one measurement includes at least one of said fluid's volume, pressure, or composition.

19. The method of claim 1 1 , further comprising transmitting said at least one measurement using a telemetry system.

20. The method of claim 19, wherein said telemetry system transmits said at least one measurement to a second downhole telemetry system.